1. Field of the Invention
The present invention relates, in general, to the field of circulating fluidized bed (CFB) boilers used to produce steam for industrial processes or electric power generation and, more particularly, to systems comprising such CFB boilers in combination with spray dryer absorbers (SDAs) used to remove acid gas compounds from gases produced during the combustion of fossil fuels in such boilers.
2. Description of the Related Art
Electric power generating plants and other industries that combust fossil fuels (e.g., coal, oil, petroleum coke, and/or waste materials) create various contaminants that include, among other things, acid gases (such as sulfur oxides) and other unwanted and/or undesirable chemical compounds in the flue gas produced during combustion.
In the 1970s, fluidized-bed combustion technology was first applied to large-scale utility boiler units to explore new ways of burning solid fuels, especially high-sulfur coal, in an environmentally acceptable and efficient manner. In concept, fluidized beds burn fuel in an air-suspended mass (or bed) of particles. By controlling bed temperature and using reagents such as limestone as bed material, emissions of nitrogen oxides (NOx) and sulfur dioxide (SO2) can be better controlled. Additional benefits of fluidized-bed combustion include wide fuel flexibility and the ability to combust fuels such as biomass or waste fuels, which are difficult to burn in conventional systems because of their low heating value, low volatile matter, high moisture content or other challenging characteristics. This technology is now used in a variety of industrial and utility boiler applications. For a better understanding of the various types of fluidized bed boilers the reader is referred to STEAM its generation and use, 41st Ed., Kitto and Stultz, eds., Copyright© 2005, The Babcock & Wilcox Company, particularly Chapter 17, the text of which is hereby incorporated by reference as though fully set forth herein.
One type of fluidized bed boiler is known as a circulating fluidized bed boiler, or CFB. CFB boilers are widely used for combusting sulfur-containing fuels since the typical CFB furnace gas temperature range allows for effective use of limestone and other alkali-containing sorbents injected into the furnace for in-furnace sulfur capture. The most commonly utilized alkali is calcium oxide, CaO, (a.k.a. lime) which reacts with sulfur dioxide in the flue gas producing calcium sulfate:CaO+SO2+½O2→CaSO4 
CFB boilers typically allow achieving a percentage of sulfur capture in the range of low-to-medium 90% without use of additional emission control equipment. Some fuels, e.g. oil shale, may even contain a sufficient amount of alkali that will allow, when fired at typical CFB furnace temperatures, a similar percentage of sulfur capture without sorbent injection.
Even though CFB boilers are quite efficient at reducing the amount of sulfur dioxides present in the flue gases, there are situations where even further sulfur oxide reductions, particularly sulfur dioxide, are required. When the required percentage of sulfur capture reaches the high 90% range, achieving this solely in the CFB furnace or reactor becomes either impossible or uneconomical. In these cases, post-combustion equipment is often required.
One of the most common methods for reducing sulfur oxides in flue gases is through a spray drying chemical absorption process, also known as dry scrubbing, wherein an aqueous alkaline solution or slurry is finely atomized (via, for example, mechanical, dual fluid, or rotary atomizers), and sprayed into the hot flue gas to remove the contaminants. For a better understanding of spray drying chemical absorption processes, or dry scrubbing, the reader is referred to STEAM its generation and use, 41st Ed., Kitto and Stultz, eds., Copyright© 2005, The Babcock & Wilcox Company, particularly Chapter 35, pages 35-12 through 35-18, the text of which is hereby incorporated by reference as though fully set forth herein.
Spray dry absorption (SDA) reflects the primary reaction mechanisms involved in the process: drying alkaline reagent slurry atomized into fine droplets in the hot flue gas stream and absorption of SO2 and other acid gases from the gas stream. The process is also called semi-dry scrubbing to distinguish it from injection of a dry solid reagent into the flue gas.
In a typical boiler installation arrangement, the SDA is positioned before the dust collector. Flue gases leaving the last heat trap (typically, air heater) at a temperature of 250° F. to 350° F. (121° C. to 177° C.) enter the spray chamber where the reagent slurry is sprayed into the gas stream, cooling the gas to 150° F. to 170° F. (66° C. to 77° C.). An electrostatic precipitator (ESP) or fabric filter (baghouse) can be used to collect the reagent, flyash and reaction products. Baghouses are the dominant selection for U.S. SDA installations (over 90%) and provide for lower reagent consumption to achieve similar overall system SO2 emissions reductions.
SO2 absorption takes place primarily while the water is evaporating and the flue gas is adiabatically cooled by the spray. Reagent stoichiometry and approach temperature are the two primary variables that control the scrubber's SO2 removal efficiency. The stoichiometry is the molar ratio of the reagent consumed to either the inlet SO2 or the quantity of SO2 removed in the process. Depending upon available reagent and acid gas content in the flue gases, the stoichiometry can vary widely; e.g., from about 1 to more than 10. The difference between the temperature of the flue gas leaving the dry scrubber and the adiabatic saturation temperature is known as the approach temperature. Flue gas saturation temperatures are typically in the range of 115° F. to 125° F. (46° C. to 52° C.) for low moisture bituminous coals and 125° F. to 135° F. (52° C. to 57° C.) for high moisture subbituminous coals or lignites. The optimal conditions for SO2 absorption must be balanced with practical drying considerations.
The predominant reagent used in dry scrubbers is lime slurry produced by slaking a high-calcium pebble lime. The slaking process can use a ball mill or a simple detention slaker. SDA systems that use only lime slurry as the reagent are known as single pass systems. Some of the lime remains unreacted following an initial pass through the spray chamber and is potentially available for further SO2 collection. Solids collected in the ESP or baghouse may be mixed with water and reinjected in the spray chamber of the SDA along with the SDA reagent.
If the fuel sulfur content is low and/or the fuel contains enough alkalis, as is known to be the case for certain types of coal and oil shale, the ash particles themselves could serve as a source of reagent in the SDA. Typically, the alkali in fuel that can produce sufficient sulfur capture is calcium carbonate (CaCO3).
Another example of ash particles being capable of serving as a reagent source in the SDA for capturing SO2 is the ash from the circulating fluidized bed (CFB) boiler. This type of boiler typically utilizes limestone, which has as its predominant component calcium carbonate, fed to the furnace for in-furnace capture of SO2 generated in the combustion process.
Whether part of the fuel or limestone, calcium carbonate in the furnace undergoes calcination, i.e. releases gaseous carbon dioxide and yields a solid calcium oxide, CaO, also known as lime:CaCO3→CaO+CO2 
The CaO reacts with SO2 in the furnace gases thus producing calcium sulfate:CaO+SO2+½O2→CaSO4 
Calcium sulfate generated in the reaction covers the surface of the particle with a shell impenetrable for SO2 thus stopping the reaction and rendering any CaO in its core unutilized.
This unutilized alkali is contained in the ash streams discharged from the CFB boiler or reactor. There are typically two major ash streams discharged from the CFB boiler: fly ash, i.e., fine particles carried with the flue gas leaving the CFB boiler, and bottom ash, i.e., coarser particles discharged at the furnace bottom.
In order to react with SO2 in the SDA, the ash particles containing alkalis have to be reactivated. This can be done by wetting them with water spray. In such a case, instead of spraying lime slurry, water will be sprayed into the flue gas in the SDA. The humidification of the particles facilitates ionic reactions of the unutilized alkali with remaining sulfur dioxide in the flue gas thus providing for sulfur capture. If the alkali slurry is injected, it will provide for sulfur capture in addition to what can be achieved by humidifying fly ash particles. This, however, will incur expenses associated with preparation and injecting the alkali slurry. Use of fly ash humidification for sulfur capture is described in R. A. Curran et al., “Cold-Side Desulfurization by Humidification of Fly Ash in CFB Boilers”, Proceedings of the 13th International Conference on Fluidized Bed Combustion, 1995.
A typical SDA process is as follows. The flue gas enters a spray dryer absorber where the gas stream is cooled by the reagent slurry or water spray. The mixture then passes on to the baghouse for removal of particulate before entering the induced draft fan and passing up the stack. If lime slurry is used as a reagent, pebble lime (CaO) is mixed with water at a controlled rate to maintain a high slaking temperature that helps generate fine hydrated lime (Ca(OH)2) particles with high surface area in the hydrated lime slurry (18 to 25% solids). A portion of the flyash, unreacted lime and reaction products collected in the baghouse may be mixed with water and returned to the SDA as a high solids (35 to 45% typical) slurry. The remaining solids are directed to a storage silo for byproduct utilization or disposal. The fresh lime and recycle slurries (if any) are combined just prior to the atomizer(s) to enable fast response to changes in gas flow, inlet SO2 concentrations, and SO2 emissions as well as to minimize the potential for scaling.
SO2 absorption in an SDA occurs in the individual slurry droplets or particles of wetted ash. Most of the reactions take place in the aqueous phase; the SO2 and the alkaline constituents dissolve into the liquid phase where ionic reactions produce relatively insoluble products. The reaction path can be described as follows:SO2(g)SO2(aq)  (a)Ca(OH)2(s)→Ca+2+2OH−  (b)SO2(aq)+H2O⇄HSO3−+H+  (c)SO2(aq)+OH−⇄HSO3−  (d)OH−+H+⇄H2O  (e)HSO3−+OH−⇄SO3−2+H2O  (f)Ca+2+SO3−2+½H2O→CaSO3.½H2O(s)  (g)
The above reactions generally describe activity that takes place as heat transfer from the flue gas to the slurry droplet or wetted ash particle causes evaporation of the slurry droplet or the water from the surface of the wetted ash particle. Rapid SO2 absorption occurs when liquid water is present. The drying rate can be slowed down to prolong this period of efficient SO2 removal by adding deliquescent salts to the reagent feed slurry. Salts such as calcium chloride also increase the equilibrium moisture content of the end product. However, since the use of these additives alters the drying performance of the system, the operating conditions must be adjusted (generally increasing the approach temperature) to provide for good long-term operability of the SDA and the ash handling system. Ammonia injection upstream of a dry scrubber also increases SO2 removal performance. SO2 absorption continues at a slower rate by reaction with the solids in the downstream particulate collector.
An SDA/baghouse combination also provides efficient control of HCl, HF and SO3 emissions by the summary reactions of:Ca(OH)2+2HCl→CaCl2+2H2O  (1)Ca(OH)2+2HF→CaF2+2H2O  (2)Ca(OH)2+SO3→CaSO4+H2O  (3)
Proper accounting of the reagent consumption must include these side reactions, in addition to the SO2 removed in the process.
Spray dryer absorbers (SDAs) can be a separate structure, or they can be an integrated part of the flue that precedes one or more particle collection devices, such as one or more baghouses or electrostatic precipitators.
Humidifying alkali-containing fly ash particles in the SDA allows further (after the CFB furnace) SO2 reduction in the flue gas and/or reduced consumption of the reagent, e.g., limestone fed to the furnace and/or lime slurry fed to the SDA. This, however, does not improve utilization of alkali contained in the bottom ash. The latter is addressed in U.S. Patent Application No. US2005/0287058 that teaches recycling part or all of the bottom ash to the CFB furnace. While improving utilization of alkali in the bottom ash, however, this method will cause an increase of NOx generation in the furnace since CaO, a predominant alkali component in the CFB ash, catalyzes oxidation of nitrogen released with fuel volatiles in the furnace.
Thus, there is a need in the art for a device and/or method for reducing the SO2 emissions and/or amount of reagent necessary for its reduction while not causing an increase in NOx generation.